1. Field of the Invention
The present invention relates generally to drill bit systems and mechanisms for drilling bores in a wide variety of materials such as earth materials for wells, rock materials for mining and various metal and polymer materials. More particularly, the present invention concerns the use of an outer drill bit that is rotated in any suitable manner and accomplishes drilling of a primary borehole. This invention also concerns an independently driven inner rotary drill bit, within the outer drill bit and which is arranged to simultaneously rotate and to move in orbital fashion to continuously and efficiently cut away the central region of the formation material that is not cut away by the outer drill bit. The present invention also concerns a drilling system that minimizes the weight or force that is applied during rotary drilling and permits efficient cutting of the formation material to achieve maximum drill bit penetration through the formation material.
2. Description of the Prior Art
While the present invention is discussed in this specification particularly from the standpoint of well drilling for the oil and gas industry, it is to be borne in mind that the spirit and scope of the present invention is applicable to the drilling of bores in other materials such as hard rock in the mining industry and for the drilling of bores in metal, wood, plastics and a wide variety of composite materials. Thus, the term “formation”, within the scope of the present invention is intended to encompass most materials that are typically capable of being drilled or machined by rotary drilling apparatus.
Drilling of oil and gas wells employs a rotary system whereby a drill bit is rotated against formation material by a “drill string” to drill a wellbore. The drill string, which is composed of connected sections of tubular drill pipe, provides a method by which a fluid, typically called “drilling fluid” or “drilling mud” is pumped through the tubular drill string allowing the fluid to exit outlet openings of a drill bit at the location of formation cutting or removal. The pumped drilling fluid provides for cooling of the drill bit and serves to flush away the drill material (soil), also called “drill cuttings”, from the drill bit location in the borehole and to convey the drill material to the surface. At the surface the drill material is separated from the drilling fluid and discarded, thereby permitting the cleaned drilling fluid to be again pumped through the drill string to the drill bit assembly. This process is generally known as drilling fluid “circulation”.
Depending on the type of material to be drilled and the design of the bit, the size of the drill bit unit will differ. The earth formation materials to be drilled have different hardness and toughness. The drilling industry has developed many different types of drill bits to accommodate the drilling of boreholes of different depths and conditions. The drilling equipment may be provided in different sizes depending on the well depth and the subsurface formation conditions that are expected to be encountered. Drilling equipment may be “onshore”, such as when land based drilling rigs are employed or may be “offshore”, such as when well drilling is accomplished from floating drilling vessels or drilling systems that are operated from stationary offshore drilling platforms that are supported by the sea floor.
The speed or rate of penetration at which wellbores are drilled in earth formations determines, in part, the overall cost of the oil or gas wells. Therefore, the efficiency of the actual drilling operations determines the length of time that is required to drill the borehole and determines the time and expense of maintaining a well drilling rig at a well site. In general, the oil and gas industry has improved the “rate of penetration”, i.e. drilling speed to a fairly efficient level over the years. Poly Diamond Crystalline “PDC” drill bits have contributed materially to the general improvement of borehole drilling. Typical PDC drill bits have some disadvantages, however, which are addressed in this specification, and which limit the rate of drill bit penetration in typical formation materials. In fact, the formation penetrating rate of most current drilling systems can be significantly improved by simple changes in drill bit design and function.
There is one area in which the oil and gas industry has failed to maximize the “rate of drill bit penetration” and that area is in hard rock drilling, which is typically encountered when wells of considerable depth are drilled or when drilling relatively hard formation material that is located at or near the surface. These areas of hard rock drilling are encountered at various depths both onshore and offshore. In the case of offshore locations, the rental or amortization costs of surface drilling equipment can be 20,000 to 500,000 US Dollars per day. It is possible that the depth of the wells can exceed depths of 30,000 feet. Therefore, large areas of hard rock drilling are typically encountered in order to reach the depth of a production formation containing paying reserves of petroleum products. In hard rock materials the drilling “rate of penetration” can be as low as one foot per hour when conventional PDC drill bits are employed. Therefore, the cost of wells can be as much as 20,000 US Dollars per foot of drilling, thus being potentially detrimental to the desired return of investment. Clearly there has been a need for a considerable period of time to provide a system for well drilling in a hard rock environment that provides for significant improvements in the rate of drill bit penetration, so that wells can be drilled and completed for production at costs that are not prohibitive.
As can be understood, any improvement in the drilling speed will significantly reduce the cost of well drilling and completion. The drilling of hard rock is being conducted at the present time through the use of “PDC” Poly Diamond Crystalline bits. The PDC bit is presently the best method to drill hard rock using PDC bits and associated systems. PDC bits employ a machining method or formation cutting action in the removal of relatively hard formation materials. As in metallic machinery or milling, a specific depth of cut is determined, (i.e. depth of cut). Similar to the metal cutting action in metallic machining, the bore material is removed by the cutting elements of the drill bit as the bit is rotated against the formation material. The number of revolutions of a drill bit per unit time and the depth of cut causes the mill to machine the bore material at a desired rate of penetration.
Drilling of oil and gas formations employs a system to remove the formation material by machinery. Therefore, the speed of rotation and “depth of cut” determines the “rate of drill bit penetration” into the formation. The above stated method is considered to be the “state of the art” at the present time. However, during drill bit rotation the cutting elements of conventional PDC drill bits achieve efficient cutting of formation material near the outer periphery of a drill bit because cutter speed relative to the formation material is optimum at the outer peripheral region of the bit. This formation cutting efficiency degrades in relation to the distance of the PDC cutting elements from the axis of rotation of the drill bit. At the inner region of a conventional PDC bit the cutter elements have much slower cutting speed relative to the formation material, which causes the efficiency of the formation cutting activity of the innermost cutting elements to be diminished. Due to the inefficient cutting capability of the cutting elements near the central portion of a drill bit the central region of the wellbore being drilled is not cut away efficiently and serves to resist forward movement of the drill bit through the formation even though the cutter elements of the outer portion of the drill bit cutting face have the capability for efficient formation cutting activity. The inefficiently cut central region of the wellbore functions as a drilling resistance region by propping up or resisting forward movement of the entire drill bit, thus retarding the rate of penetration that could otherwise be achieved. Thus, the inefficiently cut central region of a the formation being drilled to form a borehole is referred to as a “resistance region”.
During wellbore drilling as hard formation material is encountered roller cone type drill bits are typically employed for the drilling process. The roller cones of these bits have teeth that are typically faced with a hard wear resistant material such as tungsten carbide. The roller cones may also have tungsten carbide inserts when very hard formation material is encountered. As the roller cones rotate the teeth of the cones essentially chisel, chip or flake away the formation material rather than cutting it away. As certain types of hard formation material is encountered, PDC drill bits are employed and have multiple diamond cutting elements that are positioned cut away the formation material as the drill bit is rotated. As even harder formation material is encountered drill bits are employed having cutting faces that are formed of a metal substrate in which diamond cutting elements are embedded. As drilling progresses the metal substrate material will be worn away by the abrasive action of the formation material, exposing other embedded diamond cutting elements. These embedded diamond type drill bits are typically driven at higher rotary speed than other drill bits.
Regardless of the type of drill bit that is employed for drilling in hard formations the cutting elements at the outer portions of the cutting face are rotated at a speed for efficient drilling, but the innermost cutting elements, due to their much slower cutting speed, accomplish very little cutting of the formation material. Thus, as the drill bits are rotated against the formation material an inefficiently cut region of the formation at the center region of the wellbore remains and resists drill bit penetration. To enhance the efficiency of well drilling the operator of the drilling rig will typically apply relatively high drill stem weight to the drill bit so that the resistance region of the formation material being drilled is crushed by the weight of the drill string and drill bit rather than being cut away. A drill bit weight in the range of about 20,000 pounds, for example, is the typical weight for efficient cutting of the formation material by the cutting elements at the outer portion of the drill bit. Because of the efficiency retarding effect at the central resistance region of the wellbore, the driller may need to apply a drill bit weight in the range of 70,000 pounds, for example, to accomplish continual crushing of the resistance region of the formation that results due to the degradation of cutting efficiency that results from the relatively slow movement of the central cutting elements against the formation. It is desirable therefore to provide a method of formation drilling which accomplishes efficient cutting of the formation material at both the central and outer regions of a wellbore, thus eliminating the need for application of formation crushing drill bit weight and permitting the cutting elements at both the outer region and the central region of the drill bit to accomplish efficient cutting of the formation material, thus resulting in efficient drill bit penetration.
Drilling systems for deep wells typically employ a drill collar in the drill string above the drill bit. The drill collar is typically composed of stiff tubular material such as steel that resists flexing as drilling weight is applied via the drill string. The drill collar may have a length in the range of 1000 feet for deep well drilling. When a sufficiently high drill string weight is applied for crushing the formation material at the central region of the wellbore, as indicated above, even a stiff drill collar will be flexed to the point of having a portion of it establish contact with the wellbore wall. When this condition occurs the cutting face of the drill bit will be oriented at a slight angle with respect to the centerline of the drill collar, thus causing the wellbore being drilled to deviate slightly from the intended centerline of the intended wellbore. It is desirable, therefore, to provide a method for well drilling that permits the use of a sufficiently low drill bit weight that the drill collar resists any tendency for flexing and permits efficient straight ahead drilling.
The invention which is described in this specification and illustrated in the appended drawings teaches a different and improved approach to the drilling of oil and gas boreholes, whereby the “rate of penetration” of a drilling unit is significantly enhanced and the cost of well drilling is minimized.